Zero Shear Viscosifying Agent

ABSTRACT

A treatment fluid comprising an aqueous liquid and an associative polymer additive. The associative polymer additive increases the plastic viscosity (PV) of an aqueous liquid by more than at least 50% and wherein the associative polymer additive increases the yield point (YP) by no more than about 30% of the corresponding increase in the PV relative to an aqueous liquid without the associative polymer additive. Moreover, the viscosity of the aqueous liquid comprising the associative polymer additive is capable of maintaining a viscosity of greater than about 20 cP for at least 20 minutes at temperatures higher than about 275° F. In some cases the associative polymer additive may be a hydrophobic alkoxylated aminoplast.

BACKGROUND

This invention is generally related to methods and compositions fortreating subterranean formations, and more particularly to treatmentfluids having additives that modify the fluid's rheologicalcharacteristics.

Polymeric agents, such as cationic polymers, high molecular weightpolyacrylamide polymers, polysaccharides, synthetic polymers, and thelike, have previously been added to treatment fluids to obtain thedesired properties for a variety of subterranean treatments. Suchtreatments include, but are not limited to, drilling, stimulationtreatments (e.g., fracturing treatments, acidizing treatments, etc.),and completion operations (e.g., cementing, sand control treatments likegravel packing, etc.). As used herein, the term “treatment,” or“treating,” refers to any subterranean operation that uses a fluid inconjunction with a desired function and/or for a desired purpose. Theterm “treatment,” or “treating,” does not imply any particular action bythe fluid or any particular component thereof.

Traditional treatment fluids may be grouped into two classifications.Such classifications include oil-based treatment fluids andaqueous-based treatment fluids. While oil-based treatment fluids canhave superior performance characteristics, aqueous-based treatmentfluids may be more economical to use and less damaging to the formationand to the environment.

It is often important to consider a fluid's rheological parameters whenassessing the utility of a treatment fluid for a given purpose. For useas a subterranean treatment fluid, a fluid generally should be capableof maintaining a viscosity suitable for the desired operation. Forexample, a drilling fluid preferably has a sufficient viscosity to becapable of transporting the drill cuttings to the surface without beingso viscous as to interfere with the drilling operation. Similarly, acementing fluid preferably has a viscosity sufficient to preventseparation of solid cement components from the liquid components for asufficient time to allow the cement to set. However, increased fluidviscosity (e.g., cement viscosity, drilling fluid viscosity, etc.) canresult in problematic sticking of the drill string and increasedcirculating pressures that may contribute to lost circulation problemsin the formation. Solid particles such as various clays are commonlyused as a way to maintain sufficient viscosity in such treatment fluids.These solid particles may require vigorous agitation in the fluid toreach a fully active state and provide an increase in viscosity. Timepressures may demand that fluids be prepared quickly for shipment to thedrilling operation. As a result, inadequate shear and over-treatment mayoccur when using solid particles. Additionally, solid particles mayaffect both the viscosity of the fluid and the fluid's yield point,which is a measure of the initial force required to cause the fluid toflow.

In addition to prevent separation of solid cement components from theliquid components under both dynamic and static conditions, thecementing fluids should possess a low enough viscosity while under shear(during pumping) so that efficient placement of such fluids even in thenarrower annulus could be achieved, cases may be anticipated due tohighly eccentric casing placement.

Aqueous treatment fluids which do not contain solid particles may offermany advantages if they can retains the performance of an oil-basedtreatment fluid while maintaining the many of the benefits of using anaqueous-based treatment fluid.

SUMMARY

This invention is generally related to methods and compositions fortreating subterranean formations, and more particularly to treatmentfluids having additives that modify the fluid's rheologicalcharacteristics.

Some embodiments of the present invention provide methods comprisingproviding a treatment fluid comprising an aqueous fluid and anassociative polymer additive, wherein the associative polymer additiveincreases the PV of the treatment fluid by more than at least 50% andwherein the associative polymer additive increases the yield point by nomore than about 30% of the corresponding increase in the PV relative toa treatment fluid without the associative polymer additive; and placingthe treatment fluid in at least a portion of a subterranean formation.

Other embodiments of the present invention provide methods comprisingproviding a treatment fluid comprising an aqueous fluid and anassociative polymer additive, wherein the associative polymer additivecomprises hydrophobic alkoxylated aminoplast; and placing the treatmentfluid in at least a portion of a subterranean formation.

Still other embodiments of the present invention provide compositionscomprising an aqueous base fluid; an associative polymer additivecomprising a hydrophobic alkoxylated aminoplast; and at least onecompound comprising an additive selected from the group consisting of: aproppant particulate, a cement, a drill cutting, a salt, or acombination thereof.

The features and advantages of the present invention will be apparent tothose skilled in the art. While numerous changes may be made by thoseskilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention.

FIG. 1 shows the chemical composition of HASE polymers bearing n-alkylhydrophobes.

DETAILED DESCRIPTION

This invention is generally related to methods and compositions fortreating subterranean formations, and more particularly to treatmentfluids having additives that modify the fluid's rheologicalcharacteristics.

While the methods and fluids of the present invention have manyadvantages, only some will be discussed herein. One of the manypotential advantages of the methods and compositions of the presentinvention is that they may have improved suspension characteristics dueto the formation of an associative polymer network. For example, theaddition of an associative polymer additive may increase the viscosityof the treatment fluid without a corresponding increase in the yieldpoint of the fluid. Examples of treatment fluids useful in conjunctionwith the present invention may include: drilling fluids, drill-influids, cements, fracturing fluids, spacer fluids between differentfluid types (cement and drilling fluid, for example), viscous packerfluids for suspending well operations, high-viscosity sweep fluids toaid in cuttings transport, and other various tasks requiring viscousfluids. The increase in the viscosity of the fluid may aid in suspensionof particles within the fluid (e.g., proppant particulates in afracturing fluid or cementing solids in a cement composition). In anembodiment, a fluid of the present invention may demonstrate anincreased viscosity without a corresponding increase in the yield point,and the fluid may exhibit the increased viscosity without the need forsolid additives, such as weighting agents or organophilic clays.

For the purposes of describing the treatment fluids of the presentinvention, it is useful to describe certain rheological propertiesincluding yield point (“YP”), low-shear viscosity, plastic viscosity(“PV”), the equivalent circulating density (“ECD”), and yield stress(tau zero). The YP is defined as the yield stress obtained from theBingham-Plastic rheological model when extrapolated to a shear rate ofzero. It may be calculated using 300 revolutions per minute (“rpm”) and600 rpm shear rate readings on a standard oilfield rheometer. Similarly,the yield stress, or tau zero, is the stress that must be applied to amaterial to make it begin to flow (or yield), and may commonly becalculated from rheometer readings measured at rates of 3, 6, 100, 200,300 and 600 rpm. The extrapolation to determine yield stress may beperformed by applying a least-squares fit or curve fit to theHerschel-Bulkley rheological model. A more convenient means ofestimating the yield stress is by calculating the low-shear yield point(“LSYP”) by the same formula shown below in Equation 2 though with the 6rpm and 3 rpm readings substituted for the 600- and 300-rpm readings,respectively. PV represents the viscosity of a fluid when extrapolatedto infinite shear rate and may also be referred to as μ_(inf). The PVand YP are calculated by the following set of equations:

PV=(600 rpm reading)−(300 rpm reading)   (Equation 1)

YP=(300 rpm reading)−PV   (Equation 2)

The ECD is the effective circulating density exerted by a fluid againstthe formation or casing taking into account the flow rate and pressuredrop in the annulus above the point being considered. A high PV mayincrease the ECD due to a greater pressure drop in the annulus caused byinternal fluid friction.

These rheological properties may be measured using standard testingprocedures and standard testing equipment known to those skilled in theart. For example, properties such as plastic viscosity expressed incentipoises, low-shear viscosity expressed in dial readings, yield pointand LSYP expressed in lb/100 ft², and gel strength expressed in lb/100ft² may be determined by the “ANSI/API RP 10B: Recommended Practice forField Testing Oil-based Drilling Fluids,” using a 115-volt motor-drivenviscometer, such as a FANN Model 35-A V-G Meter, which is incorporatedherein by reference in its entirety. The rotational measurementsrepresent standard rates at which readings may be taken. Actualrotational rates may vary slightly and may be corrected using correctionfactors, if necessary.

The treatment fluids of the present invention comprise an aqueous basefluid and an associative polymer additive. In some embodiments, theassociative polymer additive may comprise residual monomers from theproduction of the associative polymer additive. An associative polymernetwork may be formed by the association and networking of the moleculesof the associative polymer additive polymers within the aqueous fluid.Optionally, the treatment fluids of the present invention may compriseadditional components.

The aqueous base fluids used in embodiments of the treatment fluids ofthe present invention may be fresh water, salt water (e.g., watercontaining one or more salts dissolved therein), brine (e.g., saturatedsalt water), seawater, and any combinations thereof. The brines maycontain substantially any suitable salts, including, but not necessarilylimited to, salts based on metals, such as calcium, magnesium, sodium,potassium, cesium, zinc, aluminum, and lithium. The salts may containsubstantially any anions, with preferred anions being less expensiveanions including, but not necessarily limited to chlorides, bromides,formates, acetates, and nitrates. The choice of brine may alter theassociative properties of the associative polymer additive in thetreatment fluid. A person of ordinary skill in the art, with the benefitof this disclosure, will recognize the type of brine and ionconcentration needed in a particular application of the presentinvention depending on, among other factors, the other components of thetreatment fluids, the desired associative properties of such fluids, andthe like. Generally, the aqueous fluid may be from any source, providedthat it does not contain an excess of compounds that may adverselyaffect other components in the treatment fluid. The aqueous base fluidmay be present in embodiments of the treatment fluids of the presentinvention in an amount in the range of about 5% to about 99% by weightof the treatment fluid. In certain embodiments, the base fluid may bepresent in the treatment fluids of the present invention in an amount inthe range of about 10% to about 90% by weight of the treatment fluid.

The treatment fluid of the present invention also comprises anassociative polymer additive. As used herein, an “associative polymeradditive” refers to a hydrophobically modified water-soluble polymercapable of interacting in an aqueous solution with itself and with otherspecies to form an associative network. The associative polymer additivemay generally comprise a water-soluble polymer backbone coupled to atleast one hydrophobic segment. In certain embodiments, the associativepolymer may be a linear or branched. In some instances, linear polymerbackbones may have better associative properties since they may be ableto fold back and forth with less steric hindrance. An associativenetwork formed by the interaction of the associate polymer additivemolecules in an aqueous solution may act to modify the rheologicalproperties of the treatment fluid. For example, the addition of anassociative polymer additive may increase the viscosity of the treatmentfluid without a corresponding increase in the yield point of the fluid.Such a modification may be used to make a fluid more closely modeledusing a Newtonian fluid model or a power law model.

The associative polymer additive of the present invention should beadded to the aqueous base fluid in an amount sufficient to form thedesired associative polymer networks within the treatment fluid. Incertain embodiments, the associative polymer additive may be present inamount in the range of about 0.01% to about 15% by weight of thetreatment fluid. In certain embodiments, the associative polymeradditive may be present in an amount of about 0.1% to about 4% by weightof the treatment fluid. A person of ordinary skill in the art, with thebenefit of this disclosure, will recognize the necessary amount ofassociative polymer additive to include in a particular application ofthe present invention depending on, among other factors, the othercomponents of the treatment fluids, the desired properties of theassociative polymer networks in the treatment fluids, and the like.

In an embodiment, the associative polymer additive may have a molecularweight in the range from about 10,000 to about 10,000,000. In someembodiments, the molecular weight range from about 500,000 to about1,500,000. In some embodiments, this molecular weight may vary betweenindividual associative polymer additive molecules in the treatment fluid(e.g., a range of molecular weights may be present in a treatmentfluid). One of ordinary skill in the art with the benefit of thisdisclosure will recognize the appropriate size for a given application.

Suitable associative polymer additives generally comprise hydrophobicalkoxylated aminoplast polymers such as hydrophobically modifiedethoxylated urethanes (HEUR) or hydrophobically modifiedalkali-swellable emulsions (HASE), such as ethoxylated amnioplasts andpolyethylene glycol substituted with an aminoplasts. An example of achemical constitution of a suitable HASE polymer with an n-alkylhydrophobe is shown in FIG. 1.

The hydrophobic alkoxylated aminoplast polymer may generally benon-ionic and may comprise a hydrophobic segment connected to anaminoplast through a coupling functional group. The water-solublepolymer backbone generally comprises an aminoplast. The aminoplast mayoptionally comprise additional functional groups. As used herein, anaminoplast refers to an A-stage class of thermosetting resin and isbased on the reaction product of an amine with an aldehyde and/or therelated acetals containing amines or amides. An aminoplast monomer maycomprise an amino group that may be bonded to at least one alkylol oralkylol ether or ester functional group. The functional groups mayimpart reactivity to the aminoplast monomer, allowing for the aminoplastto participate in further reactions to form a hydrophobic alkoxylatedaminoplast polymer. The skeletal unit of the aminoplast may comprise thestructure of the aminoplast minus a leaving group bonded to the alkyleneof the alkyol or alkylol ether or ester of the aminoplast, regardless ofwhether any of the leaving groups are removed from the aminoplast.

In some embodiments, the skeletal unit of the aminoplast may comprise atleast two amino groups. The skeletal unit of the aminoplast may takepart in a condensation reaction that may generate a low to moderatemolecular weight polymer, a highly crosslinked polymer byhomopolymerization or copolymerization, or a modification of theaminoplast skeletal unit to provide additional functional groups orremove some functional groups. In some embodiments, the aminoplast maybe polymerized to form an aminoplast backbone with optional, additionalfunctional groups attached to the aminoplast polymer.

In some embodiments, the hydrophobic alkoxylated aminoplast polymercomprises one or more hydrophobic segments. As used herein a hydrophobicsegment may refer to the portion of the associative polymer additivehaving at least one hydrophobe. In an embodiment, the hydrophobe maycomprise from 1 to 24 carbon atoms and may include saturate,unsaturated, aliphatic (including linear, cyclic, and branched aliphaticcompounds or groups), and/or aromatic compounds or groups. Suitablehydrophobes may include, but are not limited to, linear or branchedalkyl, alkenyl, cycloalkyl, aryl, alkaryl, aralkyl hydrocarbons, andhalo-substituted alkyl, cycloalkyl, aryl, alkylaryl, acryloyl, arylakylhydrocarbons, and mixtures thereof. While not wishing to be limited bytheory, the hydrophobic segments are believed to form associations via,e.g., physical crosslinks, Van der Waals forces, and/or electrostaticinteractions with each other or with additional components in thetreatment fluid.

In some embodiments, the hydrophobic segment may be connected to thewater-soluble polymer backbone through a coupling functional group. Thecoupling functional groups of the associative polymer additive mayprovide the reactivity and bonding sites to chemically bond thewater-soluble polymer backbone to the hydrophobic segment. The couplingfunctional group may generally comprise any functional group capable offorming a bond between the water-soluble polymer backbone and ahydrophobe. The coupling functional group may include, but is notlimited to, a group such as a hydroxyl, a carboxyl, an ether, an ester,a sulfhydryl, and an isocyanate, derivatives thereof, or combinationsthereof. Other examples of the coupling functional group may include,but are not limited to, an amino group, an ethylenic unsaturated group,an epoxide group, a carboxylic acid group, a carboxylic ester group, acarboxylic acid halide group, an amide group, a phosphate group, asulfonate group, a sulfonyl halide group, an organic silane group, anacetylene group, a phenol group, a cyclic carbonate group, an isocyanategroup, and a carbodiimide group.

In some embodiments, the number of hydrophobic segments per associativepolymer additive molecule should be sufficient to generateintermolecular interactions in an aqueous solution to allow for theformation of an associative polymer network. In an embodiment, theassociative polymer additive may generally comprise at least 0.25 toabout 25 hydrophobic segments per molecule. In some embodiments, theassociate polymer additive may comprise from about 0.5 to about 10hydrophobic segments per molecule. The number of hydrophobic segmentsper associative polymer additive molecule may be altered throughvariations in the reactant concentrations during manufacturing of theassociative polymer additive.

In some embodiments, the hydrophobic segments on the associative polymeradditive may comprise from about 5% to about 50% by weight of the totalassociative polymer molecule. In another embodiment, the hydrophobeportion of the associative polymer additive may comprise from about 10%to about 40% by weight of the total associative polymer molecule. Asnoted above, the weight fraction of the hydrophobe portion of themolecule should be sufficient to generate the desired intermolecularinteractions between the associative polymer molecules in an aqueoussolution.

The associative polymer additive that may be used to form theassociative polymer networks of the present invention may be synthesizedby incorporating hydrophobic segments within a water-soluble polymerbackbone using any suitable method. Suitable methods include chaingrowth polymerization, step growth polymerization, andpost-polymerization mechanisms for naturally occurring polymers andpolymers that were made by chain or step growth polymerization. Specificexamples may include, but are not limited to: reacting hydrophobes witha water-soluble polymer reactant containing coupling groups orcorresponding coupling group pre-cursors to form the associative polymeradditive; reacting condensation monomers and/or prepolymers along with acoupling group precursor to form condensation polymers, wherein one ofthe reactants provides the requisite hydrophobe content on the finalassociative polymer additive; and reacting olefinically unsaturatedmonomers and/or prepolymers by addition polymerization, wherein at leastone of the reactants contains the requisite hydrophobe content for thefinal associative polymer additive. In most instances, this is not apost-polymerization modification. Thus, the hydrophobic modification isincorporated within the polymer structure as it forms. However, in someinstances, this modification may be performed post-polymerization, forexample, through a suitable modification reaction. Residual monomer mayremain in the polymer.

The degree of rheological modification attributable to the associativepolymer additive may depend on a variety of factors, including, but notlimited to, the degree of hydrophobic modification on the associativepolymer additive, the microstructure of the associative polymeradditive, and the concentration of the associative polymer additive inthe treatment fluid. In certain embodiments, intrapolymer interactionsmay become more prominent at low polymer concentrations and highhydrophobic segment density along the water-soluble polymer backbone. Insuch embodiments, a compact, globular conformation may be formed givingrise to organized, hydrophobic microdomains in the network withmicelle-like properties. In other embodiments, interpolymer interactionsmay be more prominent, usually at lower hydrophobe/water-soluble polymerbackbone ratios and at higher associative polymer additiveconcentrations. A high associative polymer additive concentration maylead to chain overlap and hydrophobic clustering that increases theviscosity of the treatment fluid by forming an associative polymernetwork. One of ordinary skill in the art, with the benefit of thisdisclosure, will recognize the conditions necessary to obtain the properintrapolymer and interpolymer associations to form the associativepolymer networks of the present invention.

In some embodiments, the associative polymer additive may be used tochange the rheological properties of a treatment fluid. In someembodiments, the associative polymer additive may increase the viscosityof the treatment fluid, as measured by the PV, without a correspondingincrease in the yield point of the fluid. In some embodiments, theassociative polymer additive may increase the PV of the treatment fluidwhile limiting the increase in the yield point by no more than about 30%of the corresponding increase in the PV. In some embodiments, theassociative polymer additive may increase the PV of the treatment fluidby at least 50%. For example, if the associative polymer additiveincreases the PV of the treatment fluid by 100%, then the yield pointwould increase by no more than 30%. As an alternative example, if theassociative polymer additive increases the PV of the treatment fluid by300%, then the yield point would increase by no more than 90%. Inanother embodiment, the associative polymer additive may increase the PVof the treatment fluid while limiting the increase in the yield point byno more than about 20% of the corresponding increase in the PV.

While not intending to be limited by theory, it is believed that theassociative polymer networks that form due to the associative polymeradditive may help prevent the settling of particles in the treatmentfluid when the fluid is at rest. It is believed that the associativebonds that form when the fluid is at rest may prevent particle settling,and thus, the formation of free water in the treatment fluid. Theprevention of free water due to the formation of the associative polymernetwork may occur without a significant increase in the yield point ofthe treatment fluid. For example, a treatment fluid containing a cementmay demonstrate a reduction in the formation of free water when thesolution is not flowing; potentially increasing the final properties ofthe cement once it is set. In an embodiment, the treatment fluid maydemonstrate at least a 30% reduction in free water, or alternatively a40% reduction in free water, depending on the amount of associativepolymer additive included in the treatment fluid.

Additional additives may be included in the treatment fluids of thepresent invention as desired for a particular application, including,but not limited to, surfactants, bridging agents, polyols, fluid losscontrol agents, pH-adjusting agents, pH buffers, shale stabilizers,combinations thereof, and the like. For example, polyols may be includedin a treatment fluid and may improve thermal stability. Furthermore, avariety of additional additives suitable for use in the chosen operationmay be included in the treatment fluid as deemed appropriate by oneskilled in the art, with the benefit of this disclosure.

In some embodiments, the treatment fluids of the present invention mayhave increased thermal stability when in the presence of brine versuswater. In certain embodiments, the increase in thermal stability can beattributed to the minimization of the hydrolytic attack due to decreasedfree water in the treatment fluid. In other embodiments, it is believedthat the increase in thermal stability in aqueous base fluid may be dueto changing the contact of the aqueous media with the backbone of thepolymer chains, e.g., by facilitating the protection of the acetallinkage (e.g., 1,4-glycocidic linkage) of the backbone. The acetallinkage is thought to be generally unprotected in non-associatedunmodified polymers.

In some embodiments, surfactants may be used to facilitate the formationof the associations. It is believed that the hydrophobic groups of thenetwork forming polymers may become incorporated into surfactantmicelles, which may act as a type of crosslinker. In certainembodiments, suitable surfactants may be a non-viscoelastic surfactant.Suitable surfactants may be anionic, non-ionic, cationic, orzwitterionic. Polymeric surfactants may also be used. Aqueous liquidscontaining the surfactants may respond to shear with a Newtonian orviscoelastic behavior. Anionic surfactants with Newtonian rheologicalbehavior are preferred. Examples of suitable anionic surfactantsinclude, but are not limited to, sodium decylsulfate, sodium laurylsulfate, alpha olefin sulfonate, alkylether sulfates, alkylphosphonates, alkane sulfonates, fatty acid salts, arylsulfonic acidsalts, and combinations thereof. Examples of suitable cationicsurfactants, include, but are not limited to, trimethylcocoammoniumchloride, trimethyltallowammonium chloride, dimethyldicocoammoniumchloride, bis(2-hydroxyethyl)tallow amine,bis(2-hydroxyethyl)erucylamine, bis(2-hydroxyethyl)coco-amine,cetylpyridinium chloride, and combinations thereof. Preferably, thesurfactant chosen should show Newtonian or viscoelastic behavior whenpresent in water by itself in concentrations of less than 20%.

In certain other embodiments, the surfactant may be a viscoelasticsurfactant. The viscoelastic surfactants used in the present inventionmay comprise any viscoelastic surfactant known in the art, anyderivative thereof, or any combination thereof. The term “derivative” isdefined herein any compound that is made from one of the listedcompounds, for example, by replacing one atom in one of the listedcompounds with another atom or group of atoms, ionizing one of thelisted compounds, or creating a salt of one of the listed compounds.These viscoelastic surfactants may be cationic, anionic, nonionic, oramphoteric in nature. The viscoelastic surfactants may comprise anynumber of different compounds, including methyl ester sulfonates (e.g.,as described in U.S. patent application Ser. Nos. 11/058,660,11/058,475, 11/058,612, and 11/058,611, filed Feb. 15, 2005, therelevant disclosures of which are incorporated herein by reference),hydrolyzed keratin (e.g., as described in U.S. Pat. No. 6,547,871, therelevant disclosure of which is incorporated herein by reference),sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylatedfatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate,ethoxylated nonyl phenol), ethoxylated fatty amines, ethoxylated alkylamines (e.g., cocoalkylamine ethoxylate), betaines, modified betaines,alkylamidobetaines (e.g., cocoamidopropyl betaine), quaternary ammoniumcompounds (e.g., trimethyltallowammonium chloride, trimethylcocoammoniumchloride), derivatives thereof, and combinations thereof. The term“derivative” is defined herein to include any compound that is made fromone of the listed compounds, for example, by replacing one atom in thelisted compound with another atom or group of atoms, rearranging two ormore atoms in the listed compound, ionizing the listed compounds, orcreating a salt of the listed compound.

Suitable viscoelastic surfactants may comprise mixtures of severaldifferent compounds, including but not limited to: mixtures of anammonium salt of an alkyl ether sulfate, a cocoamidopropyl betainesurfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodiumchloride, and water; mixtures of an ammonium salt of an alkyl ethersulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, acocoamidopropyl dimethylamine oxide surfactant, sodium chloride, andwater; mixtures of an ethoxylated alcohol ether sulfate surfactant, analkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkenedimethylamine oxide surfactant; aqueous solutions of an alpha-olefinicsulfonate surfactant and a betaine surfactant; and combinations thereof.Examples of suitable mixtures of an ethoxylated alcohol ether sulfatesurfactant, an alkyl or alkene amidopropyl betaine surfactant, and analkyl or alkene dimethylamine oxide surfactant are described in U.S.Pat. No. 6,063,738, the relevant disclosure of which is incorporatedherein by reference. Examples of suitable aqueous solutions of analpha-olefinic sulfonate surfactant and a betaine surfactant aredescribed in U.S. Pat. No. 5,879,699, the relevant disclosure of whichis incorporated herein by reference. Suitable viscoelastic surfactantsalso may comprise “catanionic” surfactant systems, which comprise pairedoppositely-charged surfactants that act as counterions to each other andmay form wormlike micelles. Examples of such catanionic surfactantsystems include, but are not limited to sodium oleate (NaO)/octyltrimethylammonium chloride (C8TAC) systems, stearyl trimethylammoniumchloride (C18TAC)/caprylic acid sodium salt (NaCap) systems, and cetyltrimethylammonium tosylate (CTAT)/sodium dodecylbenzenesulfonate (SDBS)systems.

Examples of commercially-available viscoelastic surfactants suitable foruse in the present invention may include, but are not limited to,Mirataine BET-O 30™ (an oleamidopropyl betaine surfactant available fromRhodia Inc., Cranbury, N.J.), Aromox APA-T (amine oxide surfactantavailable from Akzo Nobel Chemicals, Chicago, Ill.), Ethoquad O/12 PG™(a fatty amine ethoxylate quat surfactant available from Akzo NobelChemicals, Chicago, Ill.), Ethomeen T/12™ (a fatty amine ethoxylatesurfactant available from Akzo Nobel Chemicals, Chicago, Ill.), EthomeenS/12™ (a fatty amine ethoxylate surfactant available from Akzo NobelChemicals, Chicago, Ill.), and Rewoteric AM TEG™ (a tallowdihydroxyethyl betaine amphoteric surfactant available from DegussaCorp., Parsippany, N.J.). Where used, the surfactant may be included inthe treatment fluid in an amount of about 0.1% to about 20% by weight ofthe treatment fluid. One should note that if too much surfactant is usedthat the formation of micelles in the fluid may negatively impact theoverall fluid. Representative structures of suitable surfactants for usein the present invention are shown by FIG. 7.

The treatment fluids of the present invention optionally may comprise apH buffer. The pH buffer may be included in the treatment fluids of thepresent invention to maintain pH in a desired range, inter alia, toenhance the stability of the treatment fluid. Examples of suitable pHbuffers include, but are not limited to, sodium carbonate, potassiumcarbonate, sodium bicarbonate, potassium bicarbonate, sodium orpotassium diacetate, sodium or potassium phosphate, sodium or potassiumhydrogen phosphate, sodium or potassium dihydrogen phosphate, sodiumborate, sodium or ammonium diacetate, magnesium oxide, sulfamic acid,and the like. The pH buffer may be present in a treatment fluid of thepresent invention in an amount sufficient to maintain the pH of thetreatment fluid at a desired level. One of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriate pHbuffer and amount of pH buffer to use for a chosen application.

Optionally, the treatment fluids of the present invention further mayinclude pH-adjusting compounds for adjusting the pH of the treatmentfluid, inter alia, to a desired pH for the desired operation. SuitablepH-adjusting compounds include any pH-adjusting compound that does notadversely react with the other components of the treatment fluid.Examples of suitable pH-adjusting compounds include, but are not limitedto, sodium hydroxide, potassium hydroxide, lithium hydroxide, sodiumcarbonate, potassium carbonate, fumaric acid, formic acid, acetic acid,acetic anhydride, hydrochloric acid, hydrofluoric acid, citric acid,hydroxyfluoboric acid, polyaspartic acid, polysuccinimide, ammoniumdiacetate, sodium diacetate, and sulfamic acid. The appropriatepH-adjusting compound and amount thereof may depend upon the formationcharacteristics and conditions, and other factors known to individualsskilled in the art with the benefit of this disclosure.

The treatment fluids of the present invention may comprise shalestabilizers. Examples of suitable shale stabilizers include, but are notlimited to, long chain alcohols, polyols, amine inhibitor, sodium orpotassium silicate, partially hydrolyzed polyacrylamides, polyalkeneglycols, anionic surfactants, salt solutions containing, for example,sodium chloride, potassium chloride, or ammonium chloride; cationicpolymers and oligomers, for example, poly(dimethyldiallylammoniumchloride), cationic poly(acrylamide) and cationicpoly(diemethylaminoethylmethacrylate). Generally, introducing the fluidcontaining the shale stabilizer into the portion comprises squeezing thefluid into the porosity of the portion of the subterranean formation sothat the shale stabilizer acts to at least partially stabilize theportion of the subterranean formation, e.g., by reducing the propensityof shale present in the portion of the subterranean formation to swellor migrate.

Optionally the treatment fluids of the present invention may comprisepolyols to aid in thinning or thickening the treatment fluid dependingon the desired properties. Suitable polyols are those aliphatic alcoholscontaining two or more hydroxy groups. It is preferred that the polyolbe at least partially water-miscible. Examples of suitable polyols thatmay be used in the aqueous-based treatment fluids of this inventioninclude, but are not limited to, water-soluble diols such as ethyleneglycols, propylene glycols, polyethylene glycols, polypropylene glycols,diethylene glycols, triethylene glycols, dipropylene glycols andtripropylene glycols, combinations of these glycols, their derivatives,and reaction products formed by reacting ethylene and propylene oxide orpolyethylene glycols and polypropylene glycols with active hydrogen basecompounds (e.g., polyalcohols, polycarboxylic acids, polyamines, orpolyphenols). The polyglycols of ethylene generally are thought to bewater-miscible at molecular weights at least as high as 20,000. Thepolyglycols of propylene, although giving slightly better grindingefficiency than the ethylene glycols, are thought to be water-miscibleup to molecular weights of only about 1,000. Other glycols possiblycontemplated include neopentyl glycol, pentanediols, butanediols, andsuch unsaturated diols as butyne diols and butene diols. In addition tothe diols, the triol, glycerol, and such derivatives as ethylene orpropylene oxide adducts may be used. Other higher polyols may includepentaerythritol. Another class of polyhydroxy alcohols contemplated isthe sugar alcohols. The sugar alcohols are obtained by reduction ofcarbohydrates and differ greatly from the above-mentioned polyols.Combinations and derivatives of these are suitable as well.

The choice of polyol to be used is largely dependent on the desireddensity of the fluid. Other factors to consider include thermalconductivity. For higher density fluids (e.g., 10.5 ppg or higher), ahigher density polyol may be preferred, for instance, triethylene glycolor glycerol may be desirable in some instances. For lower densityapplications, ethylene or propylene glycol may be used. In someinstances, more salt may be necessary to adequately weight the fluid tothe desired density. In certain embodiments, the amount of polyol thatshould be used may be from about 40% to about 99% by volume of thetreatment fluid.

The treatment fluids of the present invention may comprise bridgingagents. Preferably, when used, the bridging agents are eithernon-degradable, self-degrading or degradable in a suitable clean-upsolution (e.g., a mutual solvent, water, an acid solution, etc.).Examples of bridging agents suitable for use in the methods of thecurrent invention include, but are not necessarily limited to, magnesiumcitrate, calcium citrate, calcium succinate, calcium maleate, calciumtartrate, magnesium tartrate, bismuth citrate, calcium carbonate, sodiumchloride and other salts, and the hydrates thereof. Examples ofdegradable bridging agents may include, but are not necessarily limitedto, bridging agents comprising degradable materials such as degradablepolymers. Specific examples of suitable degradable polymers include, butare not necessarily limited to, polysaccharides such as dextrans orcelluloses; chitins; chitosans; proteins; orthoesters; aliphaticpolyesters; poly(lactides); poly(glycolides); poly(ε-caprolactones);poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates;poly(orthoesters); poly(amino acids); poly(ethylene oxides); andpolyphosphazenes. Combinations and derivatives of these are suitable aswell. One suitable commercially available lightweight particulate is aproduct known as “BIO VERT” manufactured by Halliburton Energy Services,Inc. of Duncan, Oklahoma. BIO VERT is a polymer material comprising90-100% polylactide and having a specific gravity of about 1.25.

When choosing a particular bridging agent to use, one should be aware ofthe performance of that bridging agent at the temperature range of theapplication. The bridging agents utilized may be generally present inthe drilling fluid compositions in an amount in the range of from about1% to about 40% by weight thereof, more preferably from about 5% toabout 25%. Generally, the bridging agents may have a particle size inthe range of from about 1 micron to about 600 microns. Preferably, thebridging particle size is in the range of from about 1 to about 200microns but may vary from formation to formation. The particle size usedis determined by the pore throat size of the formation.

The treatment fluids of the present invention also may comprise suitablefluid loss control agents. Any fluid loss agent that is compatible withthe treatment fluids of the present invention is suitable for use in thepresent invention. Examples include, but are not limited to, microgels,starches, silica flour, gas bubbles (energized fluid or foam), benzoicacid, soaps, resin particulates, relative permeability modifiers,degradable gel particulates, diesel dispersed in fluid, and otherimmiscible fluids. Another example of a suitable fluid loss controladditive is one that comprises a degradable polymer, such as thoselisted above. If included, a fluid loss additive should be added to atreatment fluid of the present invention in an amount necessary to givethe desired fluid loss control. In some embodiments, a fluid lossadditive may be included in an amount of about 5 to about 2000 lbs/Mgalof the treatment fluid. In some embodiments, the fluid loss additive maybe included in an amount from about 10 to about 50 lbs/Mgal of thetreatment fluid. For some liquid additives like diesel, these may beincluded in an amount from about 0.01% to about 20% by volume; in someembodiments, these may be included in an amount from about 1.0% to about10% by volume.

In accordance with embodiments of the present invention, the treatmentfluids of the present invention that comprise an associative polymeradditive may be used in a variety of suitable applications. By way ofexample, the treatment fluids may be used in subterranean operations,including, but not limited to, drilling operations, underbalanceddrilling operations, overbalanced drilling operations, acidizingoperations, gravel-packing operations, fracturing operations, completionoperations, and cementing operations. Among other things, the treatmentfluids may be used in subterranean fluids as drilling fluids, drill-influids, cements, spacer fluids between different fluid types (cement anddrilling fluid, for example), pills, viscous packer fluids forsuspending well operations, high-viscosity sweep fluids to aid incuttings transport, and the like. As a part of these operations,additional components may be added to the treatment fluid as would beapparent to one of ordinary skill in the art with the benefit of thisdisclosure. For example, proppant particulates may be added to thetreatment fluid as part of a fracturing fluid useful in a fracturingoperation. In another example, cement may be added along with certaincementing solids to the treatment fluid to form a cementing fluid usefulin a cementing operation. As yet another example, the treatment fluidmay comprise drill cuttings, including both macro and micro sizecuttings, when the treatment fluid is used in conjunction with adrilling operation (e.g., as a drilling fluid, a drill-in fluid, etc.).

In one embodiment, the present invention provides a method comprising:providing a treatment fluid comprising an aqueous base fluid and anassociative polymer additive, and placing the treatment fluid in asubterranean formation.

In one embodiment, the present invention provides a method comprising:providing a drilling fluid comprising an aqueous base fluid and anassociative polymer additive; and using the drilling fluid to drill atleast a portion of a well bore in a subterranean formation. Embodimentsof the present invention may include circulating the drilling fluid in awell bore while drilling.

In some embodiments, where the treatment fluids of the present inventionare used in a fracturing operation, a portion of the subterraneanformation may be contacted with the treatment fluid so as to create orenhance one or more fractures therein, the treatment fluid comprising anassociative polymer additive. The desired formulation of the treatmentfluids would be determined to obtain desired rheology.

In other embodiments, wherein the treatment fluids of the presentinvention are used in a frac pack operation, a portion of thesubterranean formation may be contacted with the treatment fluids so asto so as to create or enhance one or more fractures therein, thetreatment fluids comprising an aqueous base fluid, an associativepolymer additive, and a proppant particulate (e.g., gravel).

In other embodiments, the treatment fluids of the present invention maybe placed into the well bore as a pill either prior to or after thestabilization of unconsolidated formation particulates in a section ofthe subterranean formation penetrated by the well bore. The desiredvolume of the treatment fluids of the present invention introduced intothe well bore is based, among other things, on several properties of thesection to be treated, such as depth and volume of the section, as wellother physical properties of material in the section. The treatmentfluid may reduce fluid loss into the formation from other fluids (e.g.,carrier fluids or completion fluids) that may be introduced into thewell bore subsequent to the treatment fluid and reduce the subsequentproblems associated with water flowing into the well bore from thesubterranean formation.

In another embodiment of the present invention, the treatment fluids maybe placed into the subterranean formation as a viscosified pill duringan underbalanced drilling operation. An underbalanced drilling operationmay be referred to as a managed pressure drilling operation by someskilled in the art. Influxes from the formation may be experiencedduring an underbalanced drilling operation. Nitrogen may be used tocombat this. The treatment fluids may be recovered by pumping gas intothe formation to lift the pill out of the subterranean formation.

Another example of a method of the present invention comprises using thetreatment fluids prior to a cementing operation. In one embodiment, sucha method may comprise: providing a treatment fluid comprising an aqueousbase fluid and an associative polymer additive; introducing thetreatment fluid into a subterranean formation; allowing the treatmentfluid to suspend and carry particulates from the well bore to thesurface of a well site located above the subterranean formation;introducing a cement composition into the subterranean formation; andallowing the cement to set in the well bore. The set cement should havea tighter bond with the formation as a result.

To facilitate a better understanding of the present invention, thefollowing representative examples of certain aspects of some embodimentsare given. In no way should the following examples be read to limit, ordefine, the scope of the invention.

EXAMPLE 1

The following examples are submitted for the purpose of demonstratingthe performance characteristics of the treatment fluids of the presentinvention. These tests were conducted substantially in accordance withthe test methods described in ANSI/API RP 13B-2: Recommended Practicefor Field Testing Oil-based Drilling Fluids unless stated otherwise.

A treatment fluid was prepared by adding 5% by weight of cement of anassociative polymer additive comprising a hydrophobic ethoxylatedaminoplast (OPTIFLO® L100 available from Southern Clay Products, Inc. ofAustin, Tex.) and 0.5% by weight of cement of a fluid loss additive(Halad 344, available from Halliburton Energy Services, Inc. of Duncan,Okla.) to a 16 pound per gallon cement slurry (38.22% by weight ofcement (bwoc) fresh water and 100% bwoc class H cement). A cement slurrywithout the hydrophobic ethoxylated aminoplast was also tested toprovide comparative results. The results are provided in Tables 1 and 2.

TABLE 1 Rheological Profile of the Cement Mixture Without an Additive YPMu_(inf) K (lb/ [PV] (lb- Model 100 ft²) (cP) sec²/ft²) m n R² RUV*Newtonian 0.000 72.435 1.000 1.000 0.8229  0% Power 0.000 39.047 0.04161.000 0.447 0.9665  2% Bingham 13.753 55.571 1.000 1.000 0.9961 21%Plastic GHB-2 8.667 27.966 0.500 0.500 0.9962 27% GHB-3 11.564 42.7400.708 0.708 0.9992 100%  GHB-4 11.565 42.744 0.708 0.708 0.9992 100% Herschel- 12.235 51.256 0.0028 1.000 0.859 0.9989 77% Bulkley

TABLE 2 Rheological Profile of the Cement Mixture With an AssociativePolymer Additive YP MU_(inf) K (lb/ [PV] (lb- Model 100 ft²) (cP)sec²/ft²) m n R² RUV* Newtonian 0.000 575.383 1.000 1.000 0.9654 0%Power 0.000 652.376 0.0360 1.000 0.774 1.0000 100%  Bingham 14.007515.267 1.000 1.000 0.9925 0% Plastic GHB-2 3.848 403.336 0.500 0.5000.9980 2% GHB-3 0.050 187.057 0.200 0.200 0.9996 8% GHB-4 0.010 652.2691.000 0.774 1.0000 99%  Herschel- 0.010 652.269 0.0359 1.000 0.7741.0000 99%  Bulkley

As can be seen from the results in Tables 1 and 2, the addition of theassociative polymer additive increased the PV from approximately 56 cPto over 500 cP while only changing the YP from about 13.8 to about 14.0lb/100 ft². Further observation of the fluid during testing showed thatthe cement without the associative polymer additive exhibited settlingwhile the cement with the associative polymer additive did not. Theresults in Tables 1 and 2 also demonstrate that the modified fluid maybe represented by a power law rheological model rather than the morecomplex Bingham Plastic model.

EXAMPLE 2

A second experiment was conducted using a second associative polymeradditive (OPTIFLO® H370VF available from Southern Clay Products, Inc. ofAustin, Tex.) in a light weight cement slurry. In this case, a neat 12lb/gal cement was used as the base fluid for comparison. The associativepolymer additive is listed as a shear thinning viscosity modifyingadditive. Five slurries were created with associative polymer additiveconcentrations ranging from 0 to 3% by weight of cement. Theexperimental slurry component list is shown in Table 3.

TABLE 3 Slurry Compositions Slurry #1 Slurry #2 Slurry #3 Slurry #4Slurry#5 Water 245.0 240.3 235.6 226.1 216.7 Cement Class A 200.0 200.0200.0 200.0 200.0 optiflo H370VF  5.7  11.4  22.9  34.3 optiflo %control  0.5  1.0  2.0  3.0 Density   12 lb/gal   12 lb/gal   12 lb/gal  12 lb/gal   12 lb/gal Total Fluid 13.84 gal/sk 13.84 gal/sk 13.84gal/sk 13.84 gal/sk 13.84 gal/sk

The slurry compositions were then tested for their rheology propertiesusing ANSI/API RP 10B: Recommended Practice for Field Testing Oil-basedDrilling Fluids. In addition, samples were prepared and allowed to restin graduated flasks for 2 hours. The percentage of free water was thenmeasured as the portion of water at the top of the flask relative to thetotal fluid volume. The resulting rheological properties and free watermeasurements are shown in Table 4.

TABLE 4 Slurry Rheology and Free Water Measurements RPM 600 12 10 24 90peg 300 6.5 6 14 54 307 200 4.5 4.5 10 38 214 100 3 4 5 21 115  60 2 3.54 13 72  30 2 1.5 3 8 37  6 1 1 1 2 9  3 0.5 1 1 2 6 free water % 33 3520 1 0

As can be seen in Table 4, the standard API free water test results forthe slurries containing the associative polymer additive demonstrated areduction in the free water percentages even though the 3 and 6 RPM Fannreadings were below 10. As one or ordinary skill in the art wouldrecognize, these results indicate that slurries prepared with anassociative polymer additive will demonstrate a low YP, while stillbeing capable of providing extremely good particulate suspension.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range are specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

1-20. (canceled)
 21. A treatment fluid comprising: an aqueous liquid andan associative polymer additive, wherein the associative polymeradditive increases the plastic viscosity (PV) of an aqueous liquid bymore than at least 50% and wherein the associative polymer additiveincreases the yield point (YP) by no more than about 30% of thecorresponding increase in the PV relative to an aqueous liquid withoutthe associative polymer additive; wherein the viscosity of the aqueousliquid comprising the associative polymer additive is capable ofmaintaining a viscosity of greater than about 20 cP for at least 20minutes at temperatures higher than about 275° F.
 22. The treatmentfluid of claim 21 wherein the aqueous liquid is selected from the groupconsisting of fresh water, salt water, brine, seawater, and anycombinations thereof.
 23. The treatment fluid of claim 21 wherein theassociative polymer additive is present in from 0.01% to 15% by volumeof the treatment fluid.
 24. The treatment fluid of claim 21 wherein theassociative polymer additive comprises hydrophobic segments and whereinthe hydrophobic segments on the associative polymer additive comprisefrom 5% to 50% by weight of the total associative polymer.
 25. Thetreatment fluid of claim 21 wherein the associative polymer additivecomprises a hydrophobic alkoxylated aminoplast polymer.
 26. Thetreatment fluid of claim 21 wherein the associative polymer additive isselected from the group consisting of a hydrophobically modifiedethoxylated urethane, a hydrophobically modified alkali-swellableemulsion, and a combination thereof.
 27. The treatment fluid of claim 21wherein the treatment fluid further comprises an additive selected fromthe group consisting of a surfactant, a bridging agent, a polyol, afluid loss control agent, a pH-adjusting agent, a pH buffer, a shalestabilizer, or a combination thereof.
 28. The treatment fluid of claim21 wherein the treatment fluid is suitable for use as a drilling fluid,a drill-in fluid, a cement, a fracturing fluid, a spacer fluid, aviscous packer fluid, or a high-viscosity sweep fluid.
 29. The treatmentfluid of claim 21 wherein the treatment fluid comprises a cement andwherein the associative polymer additive decreases the formation of freewater by at least about 30% relative to a treatment fluid comprising acement without the associative polymer additive.
 30. A treatment fluidcomprising: an aqueous liquid and an associative polymer additivecomprises a hydrophobic alkoxylated aminoplast, wherein the associativepolymer additive increases the plastic viscosity (PV) of an aqueousliquid by more than at least 50% and wherein the associative polymeradditive increases the yield point (YP) by no more than about 30% of thecorresponding increase in the PV relative to an aqueous liquid withoutthe associative polymer additive; wherein the viscosity of the aqueouscomprising the associative polymer additive is capable of maintaining aviscosity of greater than about 20 cP for at least 20 minutes attemperatures higher than about 275° F.
 31. The treatment fluid of claim30 wherein the aqueous liquid is selected from the group consisting offresh water, salt water, brine, seawater, and any combinations thereof.32. The treatment fluid of claim 30 wherein the associative polymeradditive is present from 0.01% to 15% by volume of the treatment fluid.33. The treatment fluid of claim 30 wherein the associative polymeradditive comprises hydrophobic segments and wherein the hydrophobicsegments on the associative polymer additive comprise from 5% to 50% byweight of the total associative polymer.
 34. The treatment fluid ofclaim 30 wherein the treatment fluid further comprises an additiveselected from the group consisting of a surfactant, a bridging agent, apolyol, a fluid loss control agent, a pH-adjusting agent, a pH buffer, ashale stabilizer, or a combination thereof.
 35. The treatment fluid ofclaim 30 wherein the treatment fluid is suitable for use as a drillingfluid, a drill-in fluid, a cement, a fracturing fluid, a spacer fluid, aviscous packer fluid, or a high-viscosity sweep fluid.